System for injecting flue gas to a subterranean formation

ABSTRACT

A system ( 100 ) for injecting flue gas to a subterranean formation, wherein the system ( 100 ) is configured to receive an initial mixture of N 2 , CO 2  and less than 2% other components and comprises a compressor ( 110 ) for obtaining and maintaining a predetermined downhole pressure. The system ( 100 ) has a control system ( 200 ) for maintaining the amount of CO 2  in an injection mixture in the range 12-90% and can be configured for EOR.

BACKGROUND Field of the Invention

The present invention concerns a system for injecting flue gas to asubterranean formation.

Prior and Related Art

In the following description and claims, a subterranean formation is anygeological formation that can be used for storing N₂ and CO₂. Examplesinclude aquifers and reservoirs. Here, a reservoir means a layer ofporous rock, e.g. sandstone, limestone or shale, contain hydrocarbons,i.e. oil and/or natural gas.

An oilfield comprises one or more production wells, and may be locatedonshore or offshore. Each production well has a riser for conveying oilfrom a reservoir to a rig or platform on the surface. In some instances,the pressure in the reservoir is sufficient to force hydrocarbons,including oil, to the surface. However, it may be necessary or desiredto inject a fluid into the reservoir in order to maintain or increasethe pressure in the reservoir, and thereby increase the amount ofhydrocarbons produced from the reservoir. The fluid, i.e. liquid or gas,is injected into the reservoir through one or more injection wells onthe oil field. The injection wells are similar to the production wells.Indeed, a former production well may serve as injection well at a latertime in order to force oil or gas toward new production wells.

The process of injecting a fluid to increase production of hydrocarbons,i.e. from a field is known as enhanced oil recovery (EOR). Bothproduction of hydrocarbons and EOR may involve phase transitions. Forexample, methane (CH₄) is gaseous at standard conditions 1 bar and 298K, but may be liquid in a subterranean formation or solid under otherconditions. The phase transitions also depend on the fluid composition.For example, methane may form methane clathrate or ‘hydrate’ in thepresence of water. Phase transitions and their associated phase diagramsare further discussed below.

As used herein, flue gas is the gas produced by any combustion process,e.g. a fireplace, an oven, a power plant or a steam generator. A typicalflue gas from a standard combustion in air at atmospheric pressure maycontain, for example, 70-75% N₂, 10-15% O₂, 5-10% CO₂, and a smallpercentage of other components. All percentages here and in thefollowing are by mole. The other components in the flue gas dependmainly on the fuel and may include soot, CO, nitrogen oxides, sulphuroxides, noble gases etc. Fuel gas from industrial combustion, e.g. apower plant, is often treated to remove sulphur, nitrogen oxides (NOx),etc. These processes are known as ‘scrubbing’, and are not described indetail herein. Rather, it is assumed that an input gas may comprises amixture of mainly N₂, O₂ and CO₂ and less than 2% other components.

Of these, CO₂ is of particular interest because it contributes to thegreenhouse effect. Several techniques have been proposed for so-calledcarbon capture and storage (CCS), including long time storage inaquifers or depleted hydrocarbon reservoirs. As the pressure andtemperature at the reservoir differ significantly from standardconditions, i.e. 1 bar and 298 K, some or all components in a mixturemay change phase during compression and injection. Moreover, interactionbetween the components may cause the phase diagrams different fordifferent concentrations of the constituents. For example, someapplications use pure CO₂, which has a well known phase diagram andwhich is most likely liquid at the pressures and temperatures of areservoir. Due to low compressibility at these conditions, pure CO₂ maybe well suited for EOR applications. Moreover, the phase diagram can beused to avoid undesired clogging, i.e. a phase transition to solid statein pumps, pipes etc., during purification and compression. A majordisadvantage of using pure CO₂ is the cost associated with purification.

Mixtures of CO₂ and other gases have less defined properties, in generalbecause interactions between constituents cause the mix to behavedifferently than each single component. That is, each mixture has aphase diagram that depends on the components and their relativeconcentrations. A disadvantage of such systems is that differentcompositions of similar constituents may have different phases atidentical pressure and temperature. Thus, the composition of the mixturemust be controlled in addition to pressure and temperature. Some systemsare relatively well studied. There is no guarantee that all possiblefractions of CO₂ in a mixture behave in the same manner. In addition, aparticular mixture suitable for deposit in an aquifer may not be suitedfor EOR.

As an alternative to CCS methods using amines or other methods forextracting CO₂, a mixture of CO₂ and other gases can be stored after farless extensive treatment. The flue gas with mainly N₂, O₂ and 5-10% CO₂mentioned above is an example of a gas that may be deposited, e.g. in anaquifer. To avoid corrosion, bacterial growth etc., it may be desirableto reduce the amount of O₂. This may also increase efficacy. Forexample, by manipulating a combined cycle or two step combustionprocess, where the flue gas from e.g. the gas turbine is used in aclosed loop in subsequent combustion processes, it is possible to obtainO₂ levels<<1%. By utilizing high pressure in the HRSG or boiler unit andfuel with gas (e.g. pure CH₄), O₂ levels could become at the ppm level.In this way the fume gas may comprise approximately 87% N₂, 12% CO₂ andsmall amounts of other components. Such methods are provided in, forexample, WO99/64719 and NO 332044.

Phase diagrams for N₂—CO₂ mixtures with over 90 mole % CO₂ are knownfrom Goos et al., “Phase diagrams of CO₂ and CO₂—N₂ gas mixtures andtheir application in compression processes”, Energy Procedia 4 (2011)3778-3785, presented at the 10^(th) International Conference onGreenhouse Gas Control Technology (GHGT-10), and available online since1, Apr. 2011. However, obtaining high concentrations of CO₂ tends toimpose costs, e.g. for membranes or other equipment to remove N₂ and/ortime for achieving the desired result with lower process capacity.

The objective of the present invention is to provide a system solving atleast one of the problems above while retaining the benefits of priorart.

SUMMARY OF THE INVENTION

This is achieved by a system according to claim 1.

More particularly, the above objective is achieved by a system forinjecting flue gas to a subterranean formation, wherein the system isconfigured to receive an initial mixture of N₂, CO₂ and less than 2%other components and comprises a compressor for obtaining andmaintaining a predetermined downhole pressure. The system isdistinguished by a control system for maintaining the amount of CO₂ inan injection mixture in the range 12-90%.

The initial mixture is output from systems and processes brieflydiscussed in the introduction, i.e. a mixture comprising less than 2%oxygen and other components. It has been found, surprisingly, thatmixtures of N₂ and CO₂ with as little as 12% CO₂, are comparable towater for maintaining the pressure in a reservoir, and that mixtureswith 20% or more CO₂ are practically indistinguishable from water inthis respect. As a larger amount of N₂ may remain in the output gas,i.e. the gas to be injected, the costs associated with removing N₂ aredecreased. These results are also useful for injection into othersubterranean formations, notably aquifers.

Preferably, the amount of CO₂ in the injection mixture is maintained inthe range 20-90%. In this range, the properties of the mixture is nearlyindistinguishable from water as pressure support for typical reservoirpressures.

In a preferred embodiment, the compressor and injection mixture areconfigured for enhanced oil recovery.

The control system may comprise a membrane for reducing the amount ofN₂. As the N₂ exits into the ambient air, the concentration of CO₂ inthe injection mixture increases.

In addition or alternatively, the control system may comprise a mixerfor adding CO₂ to the initial mixture.

Additional features and benefits appear from the detailed descriptionand accompanying claims.

BRIEF DESCRIPTION OF THE DRAWINGS

The invention will be described in greater detail by means of exemplaryembodiments and reference to the accompanying drawings, in which:

FIG. 1 illustrates a system according to the invention;

FIG. 2 illustrates efficiency at different injection rates; and

FIG. 3 illustrates efficiency at different CO₂ concentrations.

DETAILED DESCRIPTION OF A PREFERRED EMBODIMENT

FIG. 1 is a schematic illustration of a system 100 according to theinvention. As indicated in the introduction, a flue gas from anycombustion can be treated to provide a suitable gas mixture for thepresent invention. At the system boundary 1, a treated flue gascontaining N₂, <12% CO₂ and <2% other components is assumed. Forexample, a combined cycle may be present upstream on a main feed 101 asdescribed. Similarly, an afterburner or other device (not shown) toreduce the O₂ content may be present upstream on a supply line 120 foradding CO₂ from an external source. Downstream from the system boundary2, i.e. to the right in FIG. 1, a pipeline conveys a compressedinjection mixture to a subterranean formation.

The system 100 comprises a control system 200 for controlling thecomposition of the injecting mixture, which is compressed to a desiredpressure by a compressor 110. The system 100 may comprise other parts,e.g. an intercooler 120. The intercooler 120 is a commerciallyavailable, standard system component in many compression systems.

The control system 200 comprises a membrane 210 for separating N₂ and amixer 220, e.g. a controllable valve. A sensor 230 is shown downstreamfrom the membrane 210 and mixer 220 to illustrate a feedback loop. Thesensor 230 may alternatively be disposed upstream to implement a feedforward loop. Either way, a controller 240 receives input from thesensor 230 and provides a response to an actuator, in FIG. 1 representedby the mixer 220. The controller 240 comprise hardware and software toexecute a cybernetic algorithm, e.g. a feedback or feed forwardalgorithm. The controller and algorithms are known to one skilled in theart.

In the following, we use measured values from a combined cycle as anumerical example. In particular, the initial flue gas from a typicalgas turbine contains 5% CO₂, 74% N₂, 15.5% O₂ and 5.5% other components.This O₂ content is too high for EOR applications. A secondary stepinvolving a steam generator and a steam turbine provides a referenceflue gas containing 11.4% CO₂, 86.9% N₂, 1% Ar, 0.6% O₂ and 0.03% H₂O.

This mixture can be passed through a commercially available filter inorder to reduce the content of N₂. A numerical example is provided intable 1, which is computed from the mixture above using an Aspen ProcessSimulation System, provided by Air Products Ltd. (www.airproducts.com),with a PA405N1 membrane model.

TABLE 1 Membrane filtering of reference flue gas N₂ O₂ CO₂ H₂O Ar OtherReleased   49% 0.2% 0.4% — — 0.6% Deposited 36.3% 1.7% 10.8% — 1.25% —

The row ‘Released’ contain fractions released to the atmosphere, and therow ‘Deposited’ contains the components that do not pass the membrane,and thus are eligible for injection. Disregarding the fractions releasedto the atmosphere and noting that the fraction in the ‘Deposited’ rowadd to about 50%, it is readily seen that the ‘Deposit’ fraction orinjection mixture contains about 72.6% N₂, 3.4% O₂, 21.5% CO₂ and 2.5%Ar. The value provided for Ar should be interpreted as the fraction of‘other components’, e.g. NOx.

An alternative to membrane filtering is to add CO₂ from some externalsource to achieve a fraction of CO₂ above 12%, preferably above 20%, inthe injection mixture.

Several alternatives for EOR using flue gas as injection fluid have beencompared to a base line using water as injection fluid. Moreparticularly, The Eclipse 300 2013.2 software was used for EORsimulations and the Eclipse PVTi 2013 package was applied for theassociated PVT models. First, the baseline was established using 5000 m³at 58 kg/s water injection. Next, flue gas injections was simulatedusing different gas mixtures and alternating gas injection with waterinjection. The ‘other components’ were treated as N₂ in the simulations.

The following assumptions, corresponding to sandstone, were made for thereservoir:

Porosity: from 15% to 25%, mean=19%Permeability: 160 to 650, mean=385 mD

Perm Z=(Perm X)*0.5

Netto-gross: 0.56 to 0.76 (net formation thickness contributing to oiland gas production/gross thickness of formation)Bottom of well pressure: 68 bars+Δ10 barsOil production: 5000 m³/day.

FIG. 2 illustrates the oil recovery rate or efficiency as a function oftime (15 years). The baseline 10 was obtained using water at a flow rateof 58 kg/s. The efficiency after 15 years is 28%. The curve 20represents an alternative using flue gas directly, and was obtainedusing the reference flue gas containing 11.4% CO₂ at a flow rate of 40kg/s. The efficiency after 15 years is 20.5%. Curve 22 was obtainedusing the reference flue gas, i.e. as for curve 20, but at an increasedflow rate of 80 kg/s. This case is actually better up to year 2, butthen a breakthrough from injection well to production well caused alarge area with poor sweeping effects between the wells, so that gasinjection became circulation.

FIG. 3 illustrates the oil recovery rate or efficiency as a function oftime (15 years, commencing in 2015), i.e. as in FIG. 2. The baseline 10represents water injection at 58 kg/s as in FIG. 2. Curve 30 representsa preferred alternative, i.e. a flue gas with increased CO₂ content, andwas obtained using the injection mixture with 21.5% CO₂ specified aboveat a mass flow rate 17 kg/s. Up to year 11 (2028), the oil recovery rateis identical. The efficiency after 15 years is approximately 27%.

From FIG. 3, it appears that an injection mixture of N₂ and CO₂, wherethe CO₂ fraction is above 20 mole %, has the same EOR effects as waterinjection, even with flow rates at ⅓ of the water injection rate.

The above results are generally due to the properties of N₂—CO₂ mixturesin the range 12% to 90%, in particular to the PVT-properties or phasediagrams. Thus, they may be applicable in other compressionapplications, e.g. depositing CO₂ in aquifers or other subterraneanformations.

1. A system for injecting flue gas to a subterranean formation, whereinthe system is configured to receive an initial mixture of N₂, CO₂ andless than 2% other components, the system comprising: a compressor forobtaining and maintaining a predetermined downhole pressures; and acontrol system for maintaining the amount of CO₂ in an injection mixturein the range 12-90%.
 2. The system according to claim 1, wherein theamount of CO₂ in the injection mixture is maintained in the range20-90%.
 3. The system according to claim 1, wherein the compressor andinjection mixture are configured for enhanced oil recovery.
 4. Thesystem according to claim 1, wherein the control system comprises amembrane for reducing the amount of N₂.
 5. The system according to claim1, wherein the control system comprises a mixer for adding CO₂ to theinitial mixture.